US10226734B2 - Hybrid solvent formulations for selective H2S removal - Google Patents

Hybrid solvent formulations for selective H2S removal Download PDF

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US10226734B2
US10226734B2 US15/032,765 US201415032765A US10226734B2 US 10226734 B2 US10226734 B2 US 10226734B2 US 201415032765 A US201415032765 A US 201415032765A US 10226734 B2 US10226734 B2 US 10226734B2
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acid
amine
aqueous solution
mixtures
hydroxymethyl
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US20160271558A1 (en
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Christophe R. Laroche
Gerardo Padilla
John R. Dowdle
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Dow Global Technologies LLC
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    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
    • B01D53/1493—Selection of liquid materials for use as absorbents
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
    • B01D53/1456—Removing acid components
    • B01D53/1468—Removing hydrogen sulfide
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G21/00—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents
    • C10G21/06—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents characterised by the solvent used
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G OR C10K; LIQUIFIED PETROLEUM GAS; USE OF ADDITIVES TO FUELS OR FIRES; FIRE-LIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
    • C10L3/10—Working-up natural gas or synthetic natural gas
    • C10L3/101—Removal of contaminants
    • C10L3/102—Removal of contaminants of acid contaminants
    • C10L3/103—Sulfur containing contaminants
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
    • B01D2252/10—Inorganic absorbents
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
    • B01D2252/20—Organic absorbents
    • B01D2252/202—Alcohols or their derivatives
    • B01D2252/2023—Glycols, diols or their derivatives
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
    • B01D2252/20—Organic absorbents
    • B01D2252/202—Alcohols or their derivatives
    • B01D2252/2023—Glycols, diols or their derivatives
    • B01D2252/2025—Ethers or esters of alkylene glycols, e.g. ethylene or propylene carbonate
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
    • B01D2252/20—Organic absorbents
    • B01D2252/204—Amines
    • B01D2252/20426—Secondary amines
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
    • B01D2252/20—Organic absorbents
    • B01D2252/204—Amines
    • B01D2252/20431—Tertiary amines
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
    • B01D2252/20—Organic absorbents
    • B01D2252/204—Amines
    • B01D2252/20478—Alkanolamines
    • B01D2252/20489—Alkanolamines with two or more hydroxyl groups
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
    • B01D2252/20—Organic absorbents
    • B01D2252/205—Other organic compounds not covered by B01D2252/00 - B01D2252/20494
    • B01D2252/2056—Sulfur compounds, e.g. Sulfolane, thiols
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
    • B01D2252/50—Combinations of absorbents
    • B01D2252/504—Mixtures of two or more absorbents
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
    • B01D2252/60—Additives
    • B01D2252/606—Anticorrosion agents
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
    • B01D2252/60—Additives
    • B01D2252/608—Antifoaming agents
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2256/00—Main component in the product gas stream after treatment
    • B01D2256/24—Hydrocarbons
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2256/00—Main component in the product gas stream after treatment
    • B01D2256/24—Hydrocarbons
    • B01D2256/245—Methane
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2257/00—Components to be removed
    • B01D2257/30—Sulfur compounds
    • B01D2257/302—Sulfur oxides
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2257/00—Components to be removed
    • B01D2257/30—Sulfur compounds
    • B01D2257/304—Hydrogen sulfide
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2257/00—Components to be removed
    • B01D2257/30—Sulfur compounds
    • B01D2257/306—Organic sulfur compounds, e.g. mercaptans
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2257/00—Components to be removed
    • B01D2257/30—Sulfur compounds
    • B01D2257/308—Carbonoxysulfide COS
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G OR C10K; LIQUIFIED PETROLEUM GAS; USE OF ADDITIVES TO FUELS OR FIRES; FIRE-LIGHTERS
    • C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
    • C10L2290/54—Specific separation steps for separating fractions, components or impurities during preparation or upgrading of a fuel
    • C10L2290/541—Absorption of impurities during preparation or upgrading of a fuel

Definitions

  • the invention relates generally to solvents useful for the extraction of acidic gases from oil and gas well streams. More specifically the invention relates to solvent formulations and methods for the extraction of hydrogen sulfide gases.
  • These fluid streams may be gas, hydrocarbon gases from shale pyrolysis, synthesis gas, and the like or liquids such as liquefied petroleum gas (LPG) and natural gas liquids (NGL).
  • LPG liquefied petroleum gas
  • NNL natural gas liquids
  • compositions and processes for removal of acid gasses are known and described in the literature. It is well-known to treat gaseous mixtures with aqueous amine solutions to remove these acidic gases. Typically, the aqueous amine solution contacts the gaseous mixture comprising the acidic gases counter currently at low temperature or high pressure in an absorber tower.
  • the aqueous amine solution commonly contains an alkanolamine such as triethanolamine (TEA), methyldiethanolamine (MDEA), diethanolamine (DEA), monoethanolamine (MEA), diisopropanolamine (DIPA), or 2-(2-aminoethoxy)ethanol (sometimes referred to as diglycolamine or DGA).
  • TEA triethanolamine
  • MDEA methyldiethanolamine
  • DEA diethanolamine
  • MEA monoethanolamine
  • DIPA diisopropanolamine
  • 2-(2-aminoethoxy)ethanol sometimes referred to as diglycolamine or DGA.
  • an accelerator is used in combination with the alkanolamines, for example piperazine and MDEA as disclosed in U.S. Pat. Nos. 4,336,233; 4,997,630; and 6,337,059, all of which are incorporated by reference herein in their entirety.
  • EP 0134948 discloses mixing an acid with select alkaline materials such as MDEA, to provide enhanced acid gas removal.
  • Tertiary amines such as 3-dimethylamino-1, 2-propanediol (DMAPD) have been shown to be effective at removing CO 2 from gaseous mixtures, see U.S. Pat. No. 5,736,115. Further, in specific processes, e.g., the Girbotol Process, tertiary amines have been shown effective in removal of H 2 S, but show decreased capacity at elevated temperatures, for examples see “Organic Amines-Girbotal Process”, Bottoms, R. R., The Science of Petroleum, volume 3, Oxford University Press, 1938, pp 1810-1815.
  • DMAPD 3-dimethylamino-1, 2-propanediol
  • Tertiary alkanolamines such as MDEA are inherently selective for hydrogen sulfide over CO 2 . Because of increasingly more stringent specifications towards hydrogen sulfide and sulfur dioxide emissions, there is a need for aqueous alkanolamine formulations capable of removing hydrogen sulfide selectively over CO 2 along with treating the gas to a very low level of H 2 S (i.e. 10 ppmv).
  • EP 01,134,948 discloses the use of low pKa acid additives (lower than 7) to enhance the selective removal of hydrogen sulfide.
  • the technology aims at altering vapor liquid equilibrium characteristics of the alkanolamine solvent in order to achieve lower amount of hydrogen sulfide in the treated gas.
  • U.S. Pat. No. 4,892,674 discloses the use of severely hindered alkanolamine salts as an additive for an MDEA gas treating solvent in order to enhance the selective removal of hydrogen sulfide over CO 2 compared to MDEA alone.
  • This technology is a combination of the use of severely sterically hindered amine and low pKa acid additives to MDEA based solvents.
  • US 2010/0288125 discloses the use of phosphonic acid additives in order to enhance hydrogen sulfide selective removal. The premise of this disclosure is that phosphonic acid additives are superior to known sulfuric and phosphoric acid additives.
  • the hydrogen sulfide selectivity achieved with aqueous tertiary alkanolamine solutions such as water and MDEA mixtures is limited by the hydrolysis reaction of carbon dioxide and water. It is therefore desirable to replace some or all of the water in such a mixture with a solvent that is not reactive towards CO 2 .
  • the premise of this adjustment is that hydrogen sulfide selectivity will increase by minimizing CO 2 hydrolysis.
  • U.S. Pat. No. 4,545,965 discloses a process using tertiary amines with organic solvents in substantially anhydrous ( ⁇ 2 wt % water) solutions for selective hydrogen sulfide removal.
  • the hybrid mixtures disclosed demonstrate improved selectivity compared to aqueous alkanolamine solutions. This process relies on substantially low water concentrations ( ⁇ 2 wt %), solvent with low dielectric constant, and amines with low pKa's.
  • U.S. Pat. No. 4,085,192 discloses a process for removal of hydrogen sulfide using an aqueous mixtures of alkanolamine and sulfolane.
  • the preferred amines are diisopropanolamine (DIPA) and methyldiethanolamine.
  • DIPA diisopropanolamine
  • MDEA based hybrid formulations display low acid gas carrying capacity.
  • U.S. Pat. No. 4,405,585 discloses a process and formulation for selective hydrogen sulfide removal using aqueous blends of sterically hindered amines and physical solvent (preferred solvent is sulfolane). This process relies on sterically hindered amines having a low dielectric constant. In addition, the commercial usefulness of severely sterically hindered alkanolamine is somewhat limited by their difficult preparation as exemplified by patent publication WO 2005/081778 A2.
  • U.S. Pat. No. 5,705,090 discloses hybrid formulations for selective hydrogen sulfide removal using aqueous blends of polyethylene glycols and methyldiethanolamine.
  • MDEA based hybrid formulations display low acid gas carrying capacity.
  • polyethylene glycols display a rather low dielectric constant.
  • the Amisol process uses aqueous blends of methanol and amines for selective hydrogen sulfide removal.
  • the amines include diisopropylamine (DIPA) and diethylamine which display low vapor pressure and low dielectric constant as well as diethanolamine (DEA) which is not selective for H 2 S over CO 2 .
  • DIPA diisopropylamine
  • DEA diethanolamine
  • WO 86/05474 discloses hybrid solvents for selective hydrogen sulfide removal.
  • Amines include tertiary amines and sterically hindered amines.
  • Physical solvents include glycols, glycol esters, glycol ethers, and N-methylpyrrolidone. These solutions are anhydrous ( ⁇ 5 wt % water).
  • a process for removal of sulfur gases from a gas mixture including hydrogen sulfide and carbon dioxide comprising contacting the mixture with a liquid absorbent composition including a tertiary or sterically hindered amine with a pKa of at least about 9.0 at 25° C., a physical solvent capable of providing a dielectric constant as much as 60 at 25° C. and of at least about 24 at 25° C. and preferably about 30 to about 45 at 25° C. when mixed in equal mass ratio with the amines of the invention.
  • Equal mass ratio means that when an equal weight or mass of amine is mixed with an equal mass or weight of physical solvent the desired dielectric constant is obtained.
  • Said amine preferably has a boiling point of at least 200° C.
  • tertiary amines With tertiary amines, at least one water molecule needs to be present in order to produce a protonated amine bicarbonate salt.
  • the capacity of a hybrid solvent of the invention for acid gases is a combination of the physical and chemical solubility of the gases in the solvent.
  • the dominant contribution will come from the chemical solubility.
  • Reaction products of acid gases with amines are ions which are better solvated in polar solvents. Therefore, increasingly favorable solvation free energy of the ionic products will allow for higher acid gas carrying capacity.
  • hybrid solvent mixture with higher polarity would display enhanced chemical solubility for acid gases.
  • a useful indicator to evaluate the polarity for such formulations is the dielectric constant which will be a function of the polarities of the physical solvent and the amine.
  • Chemical solubility may be further enhanced by choosing an amine with a high pKa.
  • an amine with a high pKa In the interest of maintaining selectivity for hydrogen sulfide however, we restrict our choice to non-carbamate forming amines (tertiary amines and sterically hindered amines.).
  • FIG. 1 illustrates a process flow diagram of an absorption process according the present invention.
  • FIG. 2 is a graph depicting VLE acquired by Headspace Analysis of Glycol-Amine Mixtures.
  • FIG. 3 is a graph depicting H 2 S versus CO 2 contained in treated gas at low pressure.
  • a process for the selective extraction of hydrogen sulfide using an aqueous amine solution comprising an amine, a physical solvent and a balance of water.
  • the amine solution may also comprise an acid.
  • the process of the invention uses a solution of amine useful in extracting sulfur based gases such as hydrogen sulfide from the well stream.
  • alkanolamine solutions useful in the invention are those which do not directly react with carbon dioxide to form carbamates. These are generally tertiary amines and severely sterically hindered amines. Further, it is desired for the amine to have a dielectric constant of at least about 20 and a pKa of at least 9.0 at 25° C. It is also preferred that said amine has a boiling point of at least at 200° C.
  • Amines such as 3-dimethylamino-1, 2-propanediol (DMAPD), 3-diethylaminopropane-1, 2-diol, 2-hydroxymethyl-2-dimethylaminopropane-1, 3-diol (DMTA), or 2-hydroxymethyl-2-diethylaminopropane-1, 3-diol (DETA) are examples of a tertiary amine meeting these criteria.
  • DMAPD 3-dimethylamino-1, 2-propanediol
  • DMTA 2-hydroxymethyl-2-dimethylaminopropane-1, 3-diol
  • DETA 2-hydroxymethyl-2-diethylaminopropane-1, 3-diol
  • MTA 2-hydroxymethyl-2-methylamino-1,3-propanediol
  • ETA 2-ethylamino-2-hydroxymethyl-1,3-propanediol
  • An acid may also be present in the solution used in the process of the invention.
  • the acids help to regenerate the solvent to low loadings and enhance the potency of the process.
  • Preferred acids have a pKa lower than about 7 and include phosphoric acid, phosphorus acid, hydrochloric acid, sulfuric acid, sulfurous acid, boric acid, phosphonic acid, and the like.
  • the function of the composition of the invention is to strip or sweeten oil and gas streams. Removal of acidic constituents such as H 2 S, SO 2 , CS 2 , COS, various mercaptans, and mixtures thereof is generally one of the function of the solution of the invention. Preferred functioning of the composition of the invention includes the removal of these acidic constituents in preference to carbon oxides such as CO and CO 2 .
  • PHYSICAL PROPERTIES General Preferred More Preferred Amine PkA 9.0-15.0 9.0-13.0 9.0-11.0 Dielectric constant 1 20-80 25-70 30-60
  • mixture 2 has a dielectric constant in the preferred range
  • mixture 11 which has the same physical solvent, but a less polar amine, does not.
  • the process of the present invention is preferably used to remove H 2 S and CO 2 from a gas stream comprising H 2 S and CO 2 optionally in the presence of one or more other acid gas impurities, for example N 2 , CH 4 , C 2 H6, C 3 H 8 , H 2 , CO, H 2 O, COS, HCN, NH 3 , O 2 , and/or mercaptans.
  • one or more other acid gas impurities for example N 2 , CH 4 , C 2 H6, C 3 H 8 , H 2 , CO, H 2 O, COS, HCN, NH 3 , O 2 , and/or mercaptans.
  • the present invention may be used to remove H 2 S, CO 2 and one or more of N 2 , CH 4 , C 2 H 6 , C 3 H 8 , H 2 , CO, H 2 O, COS, HCN, NH 3 , O 2 , and/or mercaptans from a gas stream comprising H 2 S, CO 2 and one or more of SO 2 , CS 2 , HCN, COS, and/or mercaptans.
  • the absorption step is conducted by feeding the fluid stream into the lower portion of the absorption tower while fresh aqueous alkanolamine solution is fed into the upper region of the tower.
  • the fluid stream freed largely from the H 2 S and CO 2 if present emerges from the upper portion (sometimes referred to as treated or cleaned gas) of the tower, and the loaded aqueous alkanolamine solution, which contains the absorbed H 2 S and CO 2 , leaves the tower near or at its bottom.
  • the inlet temperature of the absorbent composition during the absorption step is in the range of from 60° F. to 300° F., and more preferably from 80° F. to 250° F.
  • Pressures may vary widely; acceptable pressures are between 1 and 5,000 pounds per square inch (psi), preferably 2 to 2,500 psi, and most preferably 5 to 2,000 psi in the absorber.
  • the contacting takes place under conditions such that the H 2 S is preferably absorbed by the solution.
  • the absorption conditions and apparatus are designed so as to minimize the residence time of the aqueous alkanolamine solution in the absorber to reduce CO 2 pickup while at the same time maintaining sufficient residence time of the fluid stream with the aqueous absorbent composition to absorb a maximum amount of the H 2 S gas.
  • Fluid streams with low partial pressures, such as those encountered in thermal conversion processes, will require less of the aqueous alkanolamine solution under the same absorption conditions than fluid streams with higher partial pressures such as shale oil retort gases.
  • a typical procedure for the H 2 S removal phase of the process comprises absorbing H 2 S via countercurrent contact of a gaseous mixture containing H 2 S and CO 2 with the aqueous alkanolamine solution of the amino compound in a column containing a plurality of trays at a temperature, of at least 60° F., and at a gas velocity of at least 0.3 feet per second (ft/sec, based on “active” or aerated tray surface), depending on the operating pressure of the gas, said tray column having fewer than 20 contacting trays, with, e.g., 4 to 16 trays being typically employed.
  • Regeneration or desorption of the acid gases from the aqueous alkanolamine solution may be accomplished by conventional means of heating, expansion, stripping with an inert fluid, or combinations thereof, for example pressure reduction of the solution or increase of temperature to a point at which the absorbed H 2 S flashes off, or by passing the solution into a vessel of similar construction to that used in the absorption step, at the upper portion of the vessel, and passing an inert gas such as air or nitrogen or preferably steam upwardly through the vessel.
  • the temperature of the solution during the regeneration step should be in the range from 120° F. to 400° F. and preferably from 140° F.
  • the pressure of the solution on regeneration should range from 0.5 psi to 100 psi, preferably 1 psi to 50 psi.
  • the aqueous alkanolamine solution after being cleansed of at least a portion of the H 2 S gas, may be recycled back to the absorbing vessel. Makeup absorbent may be added as needed.
  • Heating of the solution to be regenerated may very suitably be affected by means of indirect heating with low-pressure steam. It is also possible, however, to use direct injection of steam.
  • the resulting hydrogen sulfide-lean aqueous alkanolamine solution may be used to contact a gaseous mixture containing H 2 S.
  • FIG. 1 represents an example of a gas treating process.
  • An aqueous amine absorbent solution is introduced via feed line 5 into the upper portion of a gas-liquid countercurrent packed-bed absorption column 2 .
  • the gas stream is introduced through feed line 1 into the lower portion of column 2 at a gas flow rate of 10 liter per minute.
  • the absorber pressure is adjusted to 238 psia.
  • the clean gas i.e., reduced amounts of H 2 S and CO 2
  • GC gas chromatography
  • the aqueous amine solution loaded with H 2 S and CO 2 flows toward the lower portion of the absorber, and leaves via line 4 .
  • the aqueous amine in line 4 is reduced in pressure by the level control valve 8 and flows through line 7 to heat exchanger 9 , which heats the loaded aqueous solution.
  • the hot rich solution enters the upper portion of the regenerator 12 via line 10 .
  • the regenerator 12 is equipped with random packing which effects desorption of the H 2 S and CO 2 gases.
  • the pressure of the regenerator is set at 17 psia.
  • the gases are passed through line 13 into condenser 14 wherein cooling and condensation of any residual water and amine occurs.
  • the gases enter a separator 15 wherein the condensed liquid is separated from the vapor phase.
  • the condensed aqueous solution is pumped via pump 22 through line 16 to the upper portion of the regenerator 12 .
  • the gases remaining from the condensation are removed through line 17 for final collection and/or disposal.
  • the regenerated aqueous solution flows down through the regenerator 12 and the close-coupled reboiler 18 .
  • the reboiler 18 equipped with an electrical heating device, vaporizes a portion of the aqueous solution to drive off any residual gases.
  • the vapors rise from the reboiler and are returned to the regenerator 12 which comingle with falling liquid and then exit through line 13 for entry into the condensation stage of the process.
  • the regenerated aqueous solution from the reboiler 18 leaves through line 19 and is cooled in heat exchanger 20 , and then is pumped via pump 21 back into absorber 2 through feed line 5 .
  • Solutions made of Water, MDEA and Ethylene Glycol (EG) are screened for H 2 S selectivity in a medium pressure pilot plant.
  • An aqueous amine absorbent solution is introduced into the pilot scale absorber FIG. 1 via feed line 5 into the upper portion of a gas-liquid countercurrent packed-bed absorption column 2 .
  • the gas stream is introduced through feed line 1 into the lower portion of column 2 at a gas flow rate of 10 liter per minute.
  • the absorber pressure is adjusted to 232 psia.
  • the clean gas i.e., reduced amounts of H 2 S and CO 2
  • the aqueous amine solution loaded with H 2 S and CO 2 flows toward the lower portion of the absorber, and leaves via line 4 .
  • Solution containing 50 wt % of amine, 25 wt % of water and 25 wt % of a physical solvent are loaded with about 1, 2.5 and 5 wt % of H 2 S and then studied by headspace analysis at 50° C. and 20 psig. The results are set forth in FIG. 2 .
  • the dielectric constant of physical solvents can be used as an indication for their polarity.
  • Solution containing 50 wt % of amine, from 25 wt % to 50 wt % of water and from 0 to 25 wt % of a physical solvent are loaded with about 0.5 mol/mol of an acid gas mixture containing various ratio of H 2 S and CO 2 and then studied by headspace analysis at 40° C. and 20 psig.
  • Solution made of MDEA, DMAPD (3-dimethylaminopropane-1, 2-diol) and water (35/5/60) acidified with 1 wt % H 3 PO 4 (solution A) is compared with a mixture containing DMAPD, water and glycerol (40/20/40) acidified with 1 wt % H 3 PO 4 (solution B) in a medium pressure pilot plant at 5 psig.
  • the results are set forth in FIG. 2 .
  • a gas stream comprising a synthetic mixture containing 4.0 percent H 2 S, 10.0 percent CO 2 and 76.0 percent N 2 , wherein percent is percent by volume, is treated in a pilot scale absorber to remove the H 2 S and CO 2 .
  • the gas stream is treated at three different flow rates.
  • Table 1 The compositions, process parameters, and residual H 2 S and CO 2 levels for Examples 1 to 5 are listed in Table 1.
  • MDEA is 98% methyldiethanolamine available from The Dow Chemical Company
  • DMAPD is 98% 3-dimethylamino-1, 2-propanediol available from AK scientific;
  • Glycerol is 98% 1, 2, 3-propanetriol available from Fisher Scientific.
  • H 3 PO 4 is an 85% o-phosphoric acid available from Fisher Scientific.
  • An aqueous amine absorbent solution is introduced into the pilot scale absorber FIG. 1 via feed line 5 into the upper portion of a gas-liquid countercurrent packed-bed absorption column 2 .
  • the gas stream is introduced through feed line 1 into the lower portion of column 2 at a gas flow rate of 10 liter per minute.
  • the absorber pressure is adjusted to 20 psia.
  • the clean gas i.e., reduced amounts of H 2 S and CO 2
  • the aqueous amine solution loaded with H 2 S and CO 2 flows toward the lower portion of the absorber, and leaves via line 4 .
  • the aqueous amine in line 4 is reduced in pressure by the level control valve 8 and flows through line 7 to heat exchanger 9 , which heats the loaded aqueous solution.
  • the hot rich solution enters the upper portion of the regenerator 12 via line 10 .
  • the regenerator 12 is equipped with random packing which effects desorption of the H 2 S and CO 2 gases.
  • the pressure of the regenerator is set at 17 psia.
  • the gases are passed through line 13 into condenser 14 wherein cooling and condensation of any residual water and amine occurs.
  • the gases enter a separator 15 wherein the condensed liquid is separated from the vapor phase.
  • the condensed aqueous solution is pumped via pump 22 through line 16 to the upper portion of the regenerator 12 .
  • the gases remaining from the condensation are removed through line 17 for final collection and/or disposal.
  • the regenerated aqueous solution flows down through the regenerator 12 and the close-coupled reboiler 18 .
  • the reboiler 18 equipped with an electrical heating device, vaporizes a portion of the aqueous solution to drive off any residual gases.
  • the vapors rise from the reboiler and are returned to the regenerator 12 which comingle with falling liquid and then exit through line 13 for entry into the condensation stage of the process.
  • the regenerated aqueous solution from the reboiler 18 leaves through line 19 and is cooled in heat exchanger 20 , and then is pumped via pump 21 back into absorber 2 through feed line 5 .
  • the flow rate for the aqueous amine absorbent is determined by slowly adjusting downward until the amount of H 2 S in the purified gas line 3 shows a dramatic increase.
  • Hybrid formulation proved to be superior to the aqueous formulation in terms of selectivity as can be seen when plotting the amount of H 2 S versus the amount of CO 2 contained in the treated gas, as shown in FIG. 3 .
  • Solutions made of MDEA or DMAPD (3-dimethylaminopropane-1,2-diol) and water acidified with 1 wt % H 3 PO 4 are compared with mixtures containing DMAPD, water and a physical solvent (50/25/25) acidified with 1 wt % H 3 PO 4 in a medium pressure pilot plant at 235 psig.
  • a gas stream comprising a synthetic mixture containing 4.2 percent H 2 S, 16.0 percent CO 2 and 79.8 percent N 2 , wherein percent is percent by volume, is treated in a pilot scale absorber to remove the H 2 S and CO 2 .
  • the gas stream is treated at three different flow rates.
  • the compositions, process parameters, and residual H 2 S and CO 2 levels for Examples 1 to 12 are listed in Table 2.
  • MDEA is 98% methyldiethanolamine available from The Dow Chemical Company
  • DMAPD is 98% 3-dimethylamino-1,2-propanediol available from AK scientific;
  • Glycerol is 98% 1,2,3-propanetriol available from Fisher Scientific;
  • EG is 98% ethylene glycol available from The Dow Chemical Company.
  • H 3 PO 4 is an 85% o-phosphoric acid available from Fisher Scientific.
  • An aqueous amine absorbent solution is introduced into the pilot scale absorber FIG. 1 via feed line 5 into the upper portion of a gas-liquid countercurrent packed-bed absorption column 2 .
  • the gas stream is introduced through feed line 1 into the lower portion of column 2 at a gas flow rate of 10 liter per minute.
  • the absorber pressure is adjusted to 250 psia.
  • the clean gas i.e., reduced amounts of H 2 S and CO 2
  • the aqueous amine solution loaded with H 2 S and CO 2 flows toward the lower portion of the absorber, and leaves via line 4 .
  • the aqueous amine in line 4 is reduced in pressure by the level control valve 8 and flows through line 7 to heat exchanger 9 , which heats the loaded aqueous solution.
  • the hot rich solution enters the upper portion of the regenerator 12 via line 10 .
  • the regenerator 12 is equipped with random packing which effects desorption of the H 2 S and CO 2 gases.
  • the pressure of the regenerator is set at 17 psia.
  • the gases are passed through line 13 into condenser 14 wherein cooling and condensation of any residual water and amine occurs.
  • the gases enter a separator 15 wherein the condensed liquid is separated from the vapor phase.
  • the condensed aqueous solution is pumped via pump 22 through line 16 to the upper portion of the regenerator 12 .
  • the gases remaining from the condensation are removed through line 17 for final collection and/or disposal.
  • the regenerated aqueous solution flows down through the regenerator 12 and the close-coupled reboiler 18 .
  • the reboiler 18 equipped with an electrical heating device, vaporizes a portion of the aqueous solution to drive off any residual gases.
  • the vapors rise from the reboiler and are returned to the regenerator 12 which comingle with falling liquid and then exit through line 13 for entry into the condensation stage of the process.
  • the regenerated aqueous solution from the reboiler 18 leaves through line 19 and is cooled in heat exchanger 20 , and then is pumped via pump 21 back into absorber 2 through feed line 5 .
  • the flow rate for the aqueous amine absorbent is determined by slowly adjusting downward until the amount of H 2 S in the purified gas line 3 shows a dramatic increase.
  • Formulation where water has been partially substituted by a physical solvent proved to exhibit superior selectivity compared to aqueous formulations. This could be seen visually by plotting the amount of H 2 S versus the amount of CO 2 contained in the treated gas as shown in FIG. 4 .

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